Use of steam assisted gravity drainage with oxygen (&#34;sagdox&#34;) in the recovery of bitumen in thin pay zones

ABSTRACT

A SAGDOX process to recover liquid hydrocarbons from at least one thin pay zone in a hydrocarbon bitumen reservoir, via a substantially horizontal production well, where the hydrocarbon bitumen reservoir has a top and a bottom. The process includes:
         i) Injecting steam into the hydrocarbon bitumen reservoir above the substantially horizontal production well;   ii) Injecting oxygen into the hydrocarbon bitumen reservoir above the substantially horizontal production well;   iii) Recovering liquid hydrocarbon gravity drainage into the substantially horizontal production well.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. application Ser. No. 14/058,488, filed on Oct. 21, 2013, which claims benefit of U.S. Application Ser. No. 61/717, 267, filed on Oct. 23, 2012 and is a CIP of U.S. application Ser. No. 13/543,012, filed on Jul. 6, 2012, which claims benefit of U.S. Application Ser. No. 61/507,196, filed on Jul. 13, 2011. U.S. application Ser. No. 14/058,488 is also a CIP of U.S. application Ser. No. 13/628,164, filed on Sep. 27, 2012, which claims benefit of U.S. Application Ser. No. 61/549,770, filed on Oct. 21, 2011 and is a CIP of U.S. application Ser. No. 13/543,012, filed on Jul. 6, 2012. U.S. application Ser. No. 14/058,488 is also a CIP of U.S. application Ser. No. 13/628,178, filed on Sep. 27, 2012, which claims benefit of U.S. Application Ser. No. 61/550,479, filed on Oct. 24, 2011. U.S. application Ser. No, 14/058,488 is also a CIP of U.S. application Ser. No. 13/888,874, filed on May 7, 2013, which claims benefit of U.S. Application Ser. No. 61/643,538, filed on May 7, 2012, and is a CIP of U.S. application Ser. No. 13/543,012, filed on Jul. 6, 2012, which claims benefit of U.S. Application Ser. No. 61/507,196, filed on Jul. 13, 2011, and said U.S. application Ser. No, 13/888,874, filed on May 7, 2013, is a CIP of U.S. application Ser. No. 13/628,164, filed on Sep. 27, 2012, which claims benefit of U.S. Application Ser. No. 61/549,770, filed on Oct. 21, 2011. U.S. application Ser. No. 14/058,488 is also a CIP of U.S. application Ser. No. 13/893,902, filed on May 14, 2013, which claims benefit of U.S. Application Ser. No. 61/647,153, filed on May 15, 2012, and is a CIP of U.S. application Ser. No. 13/543,012, filed on Jul. 6, 2012, which claims benefit of U.S. Application Ser. No. 61/507,196, filed on Jul. 13, 2011 and said U.S. application Ser. No. 13/893,902, filed on May 14, 2013 is a CIP of U.S. application Ser. No. 13/628,164, filed on Sep. 27, 2012, which claims benefit of U.S. Application Ser. No. 61/549,770, filed on Oct. 21, 2011. U.S. application Ser. No. 14/058,488 is also a CIP of U.S. application Ser. No. 13/928,839, filed on Jun. 27, 2013, which claims benefit of U.S. Application Ser. No. 61/666,116, filed on Jun. 29, 2012.

U.S. application Ser. No. 14/058,488, filed on Oct. 21, 2013, is hereby incorporated by reference in its entirety.

BACKGROUND OF THE INVENTION

Steam Assisted Gravity Drainage (“SAGD”) is a commercial thermal enhanced oil recovery (“EOR”) process, using saturated steam injected into a horizontal well, where latent heat is used to heat bitumen and lower its viscosity so it drains, by gravity, to an underlying, parallel, twin horizontal well, completed near the reservoir floor.

Since the process inception in the early 1980's, SAGD has become the dominant, in situ process to recover bitumen from Alberta's bitumen deposits (Butler, R., “Thermal Recovery of Oil & Bitumen”, Prentice-Hall, 1991). Today's SAGD bitumen production in Alberta is about 300 Kbbl/d with installed capacity at about 47 Kbbl/d (Oilsands Review, 2010). SAGD is now the world's leading, thermal EOR process.

FIG. 1 (Prior Art) shows the traditional SAGD geometry, using twin, parallel, horizontal wells 2,4 drilled in the same vertical plane, with a 5 metre spacing between the upper 2 and lower 4 wells, each well being about 800 metres long, and with the lower well 1 to 2 metres above the (horizontal) reservoir floor. Circulating steam 6 in both wells starts the SAGD process. After communication is established, the upper well 2 is used to inject steam 6 and the lower well 4 produces hot water and hot bitumen 8. Liquid production is accomplished by natural lift, gas lift, or submersible pump.

After conversion to normal SAGD operations, a steam chamber forms, around the injection 2 and production 4 wells, where the void space is occupied by steam 6. Steam condenses at the boundaries of the chamber, releases latent heat (heat of condensation) and heats bitumen, connate water and the reservoir matrix. Heated bitumen and water drain, by gravity, to the lower production well 4. The steam chamber grows upward and outward as bitumen is drained, by gravity, into the lower production well 4.

FIG. 2 (Prior Art) shows how SAGD matures. A young steam chamber 10 has bitumen drainage from steep chamber sides and from the camber ceiling. When the Chamber growth hits the top of the reservoir, ceiling drainage stops, bitumen productivity peaks and the slope of the side walls decreases as lateral growth continues. Heat losses increase (steam to oil ratio (“SOR”) increases) as ceiling contact increases and the surface area of the steam chamber increases. Drainage rates slow down as the side wall angle decreases. Eventually, the economic limit is reached and the end-of-life drainage angle is small (10-20°), as shown in FIG. 2.

Produced fluids are near saturated temperature, so it is only the latent heat of steam that contributes to the process in the reservoir. But, some of the sensible heat can be captured from surface heat exchangers (a greater fraction at higher temperatures), so a useful rule-of-thumb, for net heat contribution of steam, is 1000 BTU/lb. for the pressure (“P”) and temperature (“T”) range of most SAGD projects as best in FIG. 3 (Prior Art).

The operational performance SAGD may be characterized by measurement of the following parameters: saturated steam pressure (“P”) and temperature (“T”) in the steam chamber, as best seen in FIG. 4 (Prior Art); bitumen productivity; SOR, usually at the well head; sub-cool—the T difference between saturated steam and produced fluids; and WRR—the ratio of produced water to steam injected (also known as the water recycle ratio).

During the SAGD) process, the SAGD operator has two choices to make—the sub-cool target T difference and the operating pressure in the reservoir. A typical sub-cool target of about 10 to 30° C. is meant to ensure no live steam breaks through to the production well. Process pressure and temperature are linked (FIG. 4) and relate mostly to bitumen productivity and process efficiency. Bitumen viscosity is a strong function of temperature, as best seen in FIG. 5 (Prior Art). SAGD productivity is proportional to the square root of the inverse viscosity, as seen in FIG. 6, (Prior Art) (Butler (1991)). But, conversely if P (and T) is increased, the latent heat content of steam drops rapidly (FIG. 3) and more energy is used to heat the rock matrix as well as lost to the overburden or other non-productive areas. Increased pressure increases bitumen productivity but harms process efficiency (increases SOR). Because economic returns can be dominated by bitumen productivity, the SAGD operator typically opts to target operating pressures higher than native, hydrostatic reservoir pressures.

Despite becoming the dominant thermal EOR process, SAGD has some limitations and detractions. A good. SAGD project includes:

-   -   a horizontal well is completed near the bottom of the pay zone         to effectively collect and produce hot draining fluids.     -   injected steam, at the sand face, has a high quality.     -   process start up is effective and expedient.     -   the steam chamber grows smoothly and is contained.     -   the reservoir matrix is good quality (Φ>0.2, S_(io)>0.6,         k_(v)>2D).     -   net pay is sufficient (>15 metres).     -   proper design and control to simultaneously prevent steam         breakthrough, prevent injector flooding, stimulate steam chamber         growth to productive zones and inhibit water inflows to the         steam chamber.     -   absence of significant reservoir baffles (e.g. lean zones) or         barriers (e.g. shale).

If these characteristics are not attained or other limitations are experienced, SAGD may be impaired, as follows:

-   -   (1) The preferred dominant production mechanism is gravity         drainage and the lower production well is horizontal. If the         reservoir is highly slanted, a horizontal production well will         strand a significant resource. In other words, bitumen under the         horizontal well is not recoverable.     -   (2) The SAGD steam-swept zone has significant residual bitumen         content that is not recovered, particularly for heavier bitumens         and low-pressure steam as best seen in FIG. 7 (Prior Art). For         example with a 20% residual bitumen (pore saturation) and a 70%         initial saturation, the recovery factor is only 71%, not         including stranded bitumen below the production well or in the         wedge zone between recovery patterns.     -   (3) To “contain” a SAGD steam chamber, the oil in the reservoir         must be relatively immobile. SAGD cannot work on heavy (or         light) oils with some mobility at reservoir conditions. Bitumen         is the preferred target.     -   (4) Saturated steam cannot vaporize connate water. By         definition, the heat energy in saturated steam is not high         enough quality (temperature) to vaporize water. Field experience         also shows that heated connate water is not mobilized         sufficiently to be produced in SAGD. Produced water to oil ratio         (“WOR”) is similar to SOR. This makes it difficult for SAGD to         breach or utilize lean zone resources.     -   (5) The existence of an active water zone—either top water,         bottom water, or an interspersed lean zone within the pay         zone—can cause operations difficulties for SAGD or ultimately         can cause project failures (Nexen Inc., “Second Quarter         Results”, Aug. 4, 2011) (Vanderklippe, N., “Long Lake Project         Hits Sticky Patch”, CTV, 2011). Simulation studies concluded         that increasing production well stand-off distances may optimize         SAGD performance with active bottom waters, including good         pressure control to minimize water influx (Akram, F., “Reservoir         Simulation Optimizes SAGD, American Oil and Gas Reporter,         September 2011).     -   (6) Pressure targets cannot (always) be increased to improve         SAGD productivity and SAGD economics. If the reservoir is         “leaky”, as pressure is increased beyond native hydrostatic         pressures, the SAGD process can lose water or steam to zones         outside the SAGD steam chamber. If liquids are lost, the WRR         decreases and the process requires significant water make-up         volumes. If steam is also lost, process efficiency drops and SOR         increases. Ultimately, if pressures are too high, if the         reservoir is shallow and if the high pressure is retained for         too long, a surface break through of steam, sand and water can         occur (Roche, P., “Beyond Steam”, New Tech. Mag., September         2011).     -   (7) Steam costs are considerable. If steam costs are         over-the-fence for a utility, including capital charges and some         profits, the costs for high-quality steam at the sand face is         about $10 to 15/MMBTU. High steam costs can reflect on resource         quality limits and on ultimate recovery factors.     -   (8) Water use is significant. Assuming SOR=3, WRR=1 and a 90%         yield of produced water treatment (i.e. recycle), a typical SAGD         water use is 0.3 bbls of makeup water per bbl of bitumen         produced.     -   (9) SAGD process efficiency is “poor” and CO₂ emissions are         significant. If SAGD efficiency is defined as [(bitumen         energy)−(surface energy used)]/(bitumen energy) and bitumen         energy=6 MMBTU/bbl; energy used at sand face=1 MMBTU/bbl bitumen         (SOR˜3); steam is produced in a gas-fired boiler at 85%         efficiency; there are heat losses of 10% each in distribution to         the well head and delivery from the well head to the sand face;         usable steam energy is 1000 BTU/lb (FIG. 3) and boiler fuel is         methane at 1000 BTU/SCF; then the SAGD process efficiency=75.5%         and CO₂ emissions=0.077 tonnes/bbl bitumen.     -   (10) Steam distribution distance is limited to about 10 to 15 km         (6 to 9 miles) due to heat losses, pressure losses and the cost         of insulated distribution steam pipes (Finan, A., “Integration         of Nuclear Power . . . ”, MIT thesis, June 2007) (Energy Alberta         Corp., “Nuclear Energy . . . ”, Canadian Heavy Oil Association         pres., Nov. 2, 2006).     -   (11) Lastly, there is a “natural” hydraulic limit that restricts         well lengths or well diameters and can override pressure targets         for SAGD operations. FIG. 8 shows what can and has happened. In         SAGD, a steam/liquid interface 12 is formed. For a good SAGD         operation, with sub-cool control, the interface is between the         injector 2 and producer 4 wells. The interface is tilted because         of the pressure drop in the production well 4 due to fluid flow.         There is little/no pressure differential in the steam/gas         chamber. If the liquid production rates are too high (or if the         production well 4 is too small) the interface can be tilted so         that the toe of the steam injector 14 is flooded and/or the heel         of the producer 16 is exposed to steam breakthrough (FIG. 8).         This limitation can occur when the pressure drop in the         production well 4 exceeds the hydrostatic head between steam         injector 2 and liquids producer 4 (about 8 psi (50 kPa) for a 5         metre spacing).

Thin Pay Reservoirs (Thin Pay Zone)

For the purposes herein, “bitumen” is defined as an oil with high density (API<10) and high in situ viscosity (>100,000 cP), so that primary production is zero or very small. Bitumen is an immobile hydrocarbon under reservoir conditions.

The largest deposits are found in the Athabasca region of Alberta—the McMurray deposit (Table 1). FIGS. 9, 10, 11 and 12 characterize this deposit. FIG. 9 shows the depth of the top of the McMurray formation—i.e. the overburden thickness. FIG. 10 shows the thickness of the total McMurray deposit—both porous and non-porous zones. FIG. 11 shows the porosity internal—the net thickness of the porous portion of the deposit, with a 10% porosity cut off (this portion contains bitumen, water and gas occupy the pore volume). FIG. 12 shows the bitumen net pay thickness—a portion of the porosity interval. The difference between the porosity interval and the bitumen pay is an indication of impairment zones for EOR processes—gas, top water, bottom water or lean zones. These zones can be within the bitumen net pay or adjacent (top/ bottom).

It has been estimated that 410 billion bbls of bitumen are deposited in thin pay zones, less than 10 metres thick (Table 1) (Henrick, T. et al, “Oil Sands Research and Development, Alberta Energy Research Institute, March 2006). The vast majority of these thin pay reservoirs (zones) (380 billion bbls, 93%) are in the Athabasca region. If the thin pay cut off were set at 15 metres rather than 10 metres, the thin pay bitumen resource is larger than the carbonate bitumen resource (Table 1). By any account, thin pay bitumen in Alberta is a world-scale hydrocarbon resource.

FIG. 12 shows thin pay zones are focused on the western side of the McMurray deposit. FIG. 9 shows these deposits can have overburden depths ranging from about 100-300 metres, depending on location. Hydrostatic pressures range from about 160-500 psia, using a hydrostatic pressure gradient of 0.5 psia/ft. of depth.

FIG. 13 shows the API gravity of bitumen deposits in the McMurray formation. The bitumen density varies from 7 to 10 API, with the lighter bitumen (higher API) in the southwest part of the deposit.

Based on FIGS. 9, 10, 11, 12 and 13 we can characterize thin pay bitumen resources in Alberta as:

-   -   shallow to medium depth (100-300 m of overburden)     -   low to medium pressure (160-500 psia hydrostatic head)     -   location on the western side of the Athabasca deposit     -   high-moderate impairment for EOR (based on difference between         net porosity interval and net bitumen pay)     -   large opportunity (>400 billion bbls original bitumen in place         (“OBIP”))     -   no known technology to economically recover thin pay bitumen         (Heinrick (2006))     -   very little, if any, R&D focused on the opportunity (Heinrick         (2006))     -   API density in the 7 to 10 range     -   Thin zone, preferably less than about 25 metres, more preferably         leas than about 15 metres

The limit for SAGD minimum net-pays has been estimated as 10-15 metres (Heindrick (2006)). The factors that determine this limit are as follows:

-   -   (1) SAGD Geometry         -   It is difficult to fit a SAGD well configuration within a             net pay that is less than about 10 metres. Spacing between             the injector 2 and producer 4 horizontal wells is about 5             metres (FIG. 1). The production well is placed near the             reservoir bottom, but requires a stand-off of 1 to 2 metres.             Similarly, the upper horizontal steam injector 2 needs a             stand-off from the reservoir ceiling of a few meters. SAGD             also requires that the horizontal wells are in (or near) a             horizontal plane. If the reservoir is slanted, it is even             more difficult to fit the SAGD geometry into a thin pay             reservoir.     -   (2) Bitumen Productivity         -   The dominant economic factor for a SAGD project is the             bitumen productivity. Productivity can be affected directly             by pay thinness or by pressure, if the thin pay resource is             shallow.         -   The Gravdrain Equation (Butler (1991), FIG. 6) has been             shown to be a good predictor of productivity sensitivities.             Productivity is proportional to the square root of the net             pay. This equation can be used to predict productivity             impairments due to net pay reductions. For example, if an             ideal SAGD project with 50 metres net pay is used as the             comparison, the following productivity reductions with             smaller net pays (i.e. thin pay zones) are expected:             -   25 metres net pay—29% productivity loss             -   15 metres net pay—45% productivity loss             -   10 metres net pay—55% productivity loss             -   5 metres net pay—68% productivity loss         -   These estimates don't consider productivity losses due to             heat losses in homogeneities, pattern boundary effects,             containment losses, or pressure effects.         -   The effect of depth can be more dramatic. FIGS. 9 and 12             show that some thin pay resources are expected to be at             lower depths than most of the thick pay resources. If one is             close to the surface, it becomes too risky to operate SAGD             at overpressures. One is forced to operate near             native/hydrostatic pressures. Pressure reduction can have as             dramatic effect on bitumen productivity.         -   By using 1) the properties of saturated steam (FIG. 4); 2)             the viscosity curve for bitumen (FIG. 5); and 3) the             Gravdrain Equation (FIG. 6) to estimate productivity changes             with viscosity changes, one can estimate SAGD productivity             losses for shallower reservoirs by assuming the             following: 1) SAGD operation at hydrostatic pressures; 2) no             changes in reservoir thickness; and 3) a base case at 300             metre depth. The estimated SAGD productivity losses for             shallower reservoirs are as follows:             -   200 metre depth—15% productivity loss             -   100 metre depth—45% productivity loss             -   50 metre depth—66% productivity loss         -   The effect of reduced thickness and reduced depth are             independent and cumulative. So, if one takes a 50 metre net             pay at a 300 metre overburden depth operating at hydrostatic             pressures as a bench mark, then a 10 metre net pay at a 50             metre depth will have a productivity reduction of 85%. This             can be devastating to SAGD economics.     -   (3) Bitumen Recovery         -   In the end-of-life stage of a SAGD project, at the economic             limit, the cross section of a gravity drainage (GD) steam             chamber (in a homogenous reservoir) takes the shape of             linear, sloped drainage channels, with a fixed drainage             angle (FIG. 2). If one assumes a sharp break between the             steam-swept zone and the un-swept zone, and if one knows the             drainage angle at end-of-life, one can calculate the             recoverable reserves. FIG. 14 shows this calculation for a             base-case SAGD project (25 metre net pay, 100 metre well             spacing, 1 metre offset of bottom well, Φ=0.35, S_(io)=0.8,             S_(ro)=0.15, θ=15°). The recovery factor for such a project             is 56% OBIP—a typical expectation for SAGD.         -   FIGS. 15, 16, 17 show some calculations for a 10 metre thin             pay reservoir, assuming the same performance. Well spacings             are for 100 metres (the same as our base case), 67.2 metres             so the drainage interface intersects the corner of the             recovery pattern, and 29.8 metres so that recoveries are             similar to the base case.         -   The results can be summarized as follows:

Base A B C Net Pay (metres) 25 10 10 10 Well Spacing (metres) 100 100 67.2 29.8 Recovery Factor (metres) 0.562 0.213 0.366 0.568

-   -   -   So if we wish to have the same spacing as our base case,             bitumen recovery (0.213) is unacceptable. If we keep the             same recovery (˜0.56), we have to reduce well spacing from             100 metres to 29.8 metres. We are increasing well density by             a factor of more than 3. This will increase capital expenses             considerably per unit bitumen produced.

    -   (4) Economic Limitations         -   To illustrate the economic issues and concerns for SAGD in             thin pay bitumen reservoirs, we have constructed a simple             model for end-of-life SAGD as shown in FIG. 18, with the             following key assumptions:         -   A 2 metre stand-off of the lower production well from the             bottom of the reservoir:         -   The aspect ratio (pattern width:pattern thickness) is 4.             This results in a drainage angle of end-of-life at 10-13°;         -   Base case for 25 m net pay. Recovery rate equalized over 10             yrs. (S_(io)=0.80, S_(ro)=0.15, Φ=0.35);         -   The average productivity for thin reservoirs is reduced             according to FIG. 6 (no accounting for shallowness of net             pay zone);         -   Assuming a $10/bbl net back for bitumen (to the well head)             we calculate cumulative net backs at 0, 10 and 20% of             discount rates.

    -   For a 1000 metre length SAGD well pair geometry, we calculate         the following:

pay thickness (m) 7 10 15 25 Well spacing (m) 28 40 60 100 Bitumen Recovery (Mbbl) .150 .344 .837 2.469 Recovery Factor .44 .49 .52 .56 Avg. Prod. (bbl/d) 358 428 525 677 Lifetime (yrs) 1.15 2.20 4.37 10.0 Cash Flow ($M) PV₀ 1.50 3.44 8.37 24.69 PV₁₀ 1.35 2.97 6.51 15.19 PV₂₀ 1.23 2.57 5.25 10.36

-   -   This simple model doesn't penalize the productivity of thin pay         reservoirs due to reduced pressures (shallow resources), or heat         losses proportionately larger than our base case, or start-up         delays (instant start up is assumed). So, thin pay productivity         is probably optimistic.     -   Based on our model we observe the following;         -   The end-of-life drainage angles (10-13°) are realistic for             SAGD. The recovery factors are reasonable (44 to 56%).         -   In order to recover a reasonable amount of the resource,             using SAGD, thin pay reservoir well spacing must be reduced             considerably, (e.g. 40 metre spacing for 10 metre net pay             zone).         -   If one can achieve productivities impaired only by pay             thickness reduction (i.e. other factors are constant), thin             pay resources are depleted very quickly (e.g. 2.2 yrs. for             10 m net pay)         -   The model assumes instant (avg.) productivity in year 1.             Delays would hurt economics for thin pays more severely             because of the short run lengths.         -   If one assumes a serviced, SAGD, 1000 metre well-pair costs             $5-10 million, one sees a pay cut off of about 15 metre.         -   If net backs for bitumen were double, at $20/bbl, pay cut             offs could be less than 15 metre for SAGD.         -   If one maintains a 2 metre stand off from reservoir bottom             and if one also maintains a 5 metre spacing between steam             injection and producer well, SAGD cannot be applied to             reservoirs with less than 7 metre pay thickness.         -   FIG. 19 shows how the unrecovered bitumen, at end-of-life             SAGD, is distributed between wedge zones, the portion of the             reservoir underneath the plane of the production well and             residual bitumen in the steam-swept zone. As the net pay is             reduced, the bitumen beneath the plane of the production             well becomes the most important unrecovered resource, unlike             thick SAGD, where the wedge zone bitumen dominates.     -   (5) Recovery Inhomogeneties         -   So far, concerns with SAGD applied to thin reservoirs that             are homogeneous have been discussed. But, no reservoir is             truly homogeneous. Shale, mudstones, lean zones, top/bottom             water, and top gas can all contribute to inhomogeneities.         -   SAGD is a mild process. It can also be termed as a delicate             process. Production is driven by the gravity head in the             reservoir. The hydrostatic gravity head for a 30 metre pay             reservoir is very low-about only 50 psia (maximum). The             gravity gradient is only about 0.5 psi/ft, or 1.6 psi/m.             SAGD is also a 2D process. There are no significant             reservoir flows in the direction of the horizontal wells.             Water in the reservoir or in an inhomogenity cannot be             vaporized by SAGD. For this reason, in a homogeneous             reservoir, a Hele-Shaw 2D physical model can be a good             predictor of actual SAGD performance. Also, SAGD             temperatures are limited to saturated steam conditions.         -   For these reasons above, SAGD has difficulty to overcome any             reservoir inhomogeneities that can disrupt flow patterns.     -   (6) Recovery Efficiency         -   The usual efficiency measure for SAGD is SOR. SOR is             inversely related to efficiency—low SOR˜high thermal             efficiency. SOR is determined by the energy needed to heat             up the reservoir matrix, the energy needed to heat up the             reservoir fluids (bitumen and water) and the heat lost to             overburden and underburden (both during transit down the             injection well and direct losses in the reservoir at the             over/underburden interfaces). At lower steam pressures, SOR             is reduced because less heat is needed to heat the reservoir             and compensate for losses to over/underburden. Thin pay             deposits will have increased losses to overburden because             the steam interface will hit the ceiling quicker than for             thick pay resources. Everything else being equal, energy             losses to overburden are proportional to the surface area of             the ceiling. Ceiling surface area per unit OBIP is             proportional to (l/h) where h=net pay. Using this             relationship, we can expect heat losses per unit OBIP to be             2.5 times greater for 10 metre pay reservoir compared to a             25 metre pay reservoir. So, in addition and to the concerns             already expressed, (productivity and recovery factor), thin             pay bitumen SAGD will have higher SOR (lower thermal             efficiency) than thick pay bitumen SAGD.     -   (7) Summary     -   In summary, SAGD in thin pay bitumen reservoirs has the         following deficiencies:         -   It becomes difficult, using traditional SAGD geometry             (FIG. 1) to fit the wells within the reservoir.         -   Compared to thicker-pay reservoirs, thin pay bitumen             reservoirs will have significant bitumen productivity             reductions.         -   If the thin pay reservoir is shallow and SAGD is forced to             operate at pressures near to native reservoir pressure,             bitumen productivity is further reduced.         -   Unless well spacing is reduced, increasing well costs,             bitumen recovery is poor compared to thicker pay bitumen             resources.         -   Revenues, generated by thin pay bitumen recovery, are             significantly less than revenues from thicker-pay resources.             Even when productivity is reduced, accounting for reduced             gravity heads, thin pay production may only last for a few             years compared to over 10 years for thicker pay resources.         -   SAGD is sensitive to reservoir impairments (shales, lean             zones . . . etc.). If these impairments are proportionately             more prevalent in thin pay reservoirs, SAGD will have             problems as discussed herein.         -   Heat losses can reduce process of efficiency. Thin pay             reservoirs will have greater heat losses to overburden or             underburden than thicker-pay resources.

Despite the deficiencies of SAGD, it is still being considered for thin pay bitumen recovery. Husky has proposed $35 million, thin pay SAGD project at McMullen, Alberta, with 10 to 16.5 ‘metre net pay zone in the Wabaskaw formation (Roche, P., “No Analogue”, New Tech. Mag. Apr. 1, 2009). The generally accepted pay thickness limit for SAGD is 15 metres, but this may be pushed downward to 10 metres.

Based on the previous analysis, desirable attributes improvements or new bitumen EOR processes for thin pay resources are as follows:

-   -   Reduce the well costs, per bbl, of bitumen recovered. This can         be accomplished by new well configurations, reduced well sizes,         longer (horizontal) wells, or the use of well components that         are retrievable and reusable.     -   Reduce the unit operating expenses. This can be accomplished by         injecting energy that is less costly than steam or by using         processes that require less energy to produce bitumen.     -   Increase bitumen productivity. This can be accomplished by         processes that run hotter than SAGD, introduce new recovery         mechanisms, or increase well lengths.     -   Increase productivity in impaired reservoirs. This can be         accomplished by processes that are 3 dimensional, processes that         can more easily breach barriers (e.g. vaporize water . . . ) or         processes that run hotter than SAGD.     -   Increase ultimate recovery. This can be accomplished by         processes that recover some residual bitumen from a steam-swept         zone, or recover more oil from wedge zones between recovery         patterns.     -   Increase produced bitumen value. This can be accomplished by         partial in situ upgrading.     -   Improve environmental performance. This can be accomplished by         reducing (make-up) water use, increasing process efficiency,         reducing CO₂ emissions or reducing surface footprints.

In addition to SAGD, the following processes have been suggested as applicable for thin pay bitumen recovery:

-   -   (i) Expanding Solvent SAGD (ESSAGD) has been suggested as a         process to target thin pay (Gates, I. “Solvent Aided SAGD in         thin oil sand reservoirs, Journal of Petroleum Science and         Engineering Apr. 24, 2010). The idea is simply that steam and         solvent is more effective than steam alone. Solvent dissolution         in bitumen can lower viscosity and provide a separate recovery         mechanism compared to steam alone. But, the process has the         following deficiencies:         -   The operating temperature is lower than SAGD at the same P,             because steam is diluted by solvent gas. Heat losses can be             reduced, but productivity, due solely to bitumen heating, is             also reduced compared to SAGD.         -   The process geometry is similar to SAGD. The process is a 2D             process, with no reservoir flows in the longitudinal             direction. Well costs (capital expenses) are similar to             SAGD.         -   Solvent (butane, condensate, BTX . . . ) is very costly             (more valuable than bitumen). If there are any net solvent             losses to the reservoir (leakage, retention), operating             expenses can be comparable or higher than SAGD.         -   The extent of solvent losses is unknown until the end of the             project.         -   No field tests for ESSAGD in thin pay bitumen, have been             conducted.     -   (ii) It has also been suggested that SAGD geometry can be         altered, in thin pay reservoirs, by offsetting the upper steam         injector in a lateral direction, or by adding a multi-lateral         producer to the SAGD geometry (Tavallali, “Assessment of SAGD .         . . ” SPE 153128, March 2012). However, the process has the         following deficiencies:         -   Capital expense is similar to SAGD. The well count and             length are unchanged.         -   The focus of the process is on heavy oil not bitumen.         -   Other SAGD concerns—poor productivity, poor energy             efficiency, and poor recovery or increased well spacing—are             retained by this technology.     -   (iii) It has also been suggested to replace the parallel SAGD         steam injector with a series of overlapping perpendicular         horizontal injector wells (Stalder. “Cross SAGD (XSAGD) . . . ”         SPE Reservoir Evaluation & Engineering, 2007). The process is         called cross SAGD or XSAGD. This forms a grid of parallel         horizontal steam injectors intersecting (at a spacing similar to         SAGD (5 metres)) a grid of parallel horizontal producers. XSAGD         deficiencies are similar to (ii) above.     -   (iv) Solvents without steam have also been suggested, using a         VAPEX process (New Tech Mag., “VAPEX shows promise but stuck in         lab”, 2005). But this pure solvent process has the following         deficiencies:         -   The processes have been proven in field tests to be             difficult (slow) to start.         -   Productivity has been much less than SAGD.         -   Solvents are expensive (more costly than bitumen), so that,             even with modest losses, operating expenses are a concern.         -   The processes are 2D, without longitudinal flows in the             reservoir.         -   Focus has shifted to heavy oils (with some initial             injectivity) not to bitumen.         -   Solvent losses (to the reservoir) are a key economic             concern. Unfortunately, net losses cannot be confirmed until             the end of the project, when solvents are expected to be             recovered in a blow-down phase.     -   (v) Single Well SAGD (“SWSAGD”) is another EOR alternative for         thin pay bitumen and heavy oil applications (Elliot, K. et al,         “Computer Simulation of SWSAGD”, U.S. Department of Energy,         14994-18, July 1999) (ELAN Energy, “Announces Six Month         Results”, August 1996) (Improved Recovery Week, “Thermal System         ups heavy oil . . . ”, Dec. 4, 1995). The idea is to incorporate         steam 6 injection and bitumen+water 8 production into a single         horizontal well, using thermal packers 18 (FIG. 20) (or not         (FIG. 21), in order to isolate steam 6 injection and         bitumen+water 8 production.     -   The original targets were thin heavy oil deposits in W.         Saskatchewan and E. Alberta (Ashok, K. et al, “A Mechanistic         Study of SWSAGD”, Society of Petroleum Engineers,         59333-MS, 2000) (ELAN Energy, “Announces Nine Month Earnings,         November 1996) (Luft, H. B. et al, “Thermal Performance of         Insulated Concentric Coiled Tubing (ICCT) for Continuous . . . ,         “SPE, 37534-MS, 1997). The first SWSAGD well was drilled at         Cactus Lake, Saskatchewan in 1995 (HOSC (Heavy Oil Sci. Cent)         “Completions and Workovers”, www.lloydminsterheavyoil.com,         2012). Several field tests were conducted by Elan and others in         the 1990s (Elliot (1999), (Saltuklaroglu, M. at al, “Mobil's         SAGD Experience at Celtic, Saskatchewan” SPE, 99-25, June 1999).     -   Compared to SAGD, SWSAGD has a definite longitudinal flow so it         can more easily deal with barriers and it has a definite reduced         well cost. But, the following concerns were also evident:         -   The centralized concentric steam line 6 is in contact with             the produced fluids (water+bitumen 8) (FIGS. 20, 21). The             produced fluids have a high heat capacity and normally (i.e.             SAGD) the fluids would be at a lower temperature than             saturated-steam (i.e. sub-cool control). Heat losses from             the steam injector to the produced fluids can be             considerable for uninsulated, concentric, carbon steel             tubing. Heat losses from the steam 6 and produced liquids 8             are also a concern because the produced liquids have a high             heat conductivity. The produced fluids 8 are heated rapidly             to saturated steam temperatures and the steam quality is             reduced considerably before injection to the reservoir. The             use of a steam trap (sub cool) control for production rates             will be difficult, at best. One solution is to use insulated             tubing for the steam injection tube. Insulated concentric             coiled tubing (ICCT) was developed for this purpose but has             not resulted in widespread use today (Luft, H. B. et al.             “Thermal Performance of Insulated Concentric Coiled Tubing             (ICCT) for Continuous . . . , “SPE, 37534-MS, 1997)             (Falk, K. et al “Concentric Coiled Tubing for SWSAGD”, World             Oil, July 1996).         -   Start-up performance is another issue. Even for heavy oil             deposits with some steam injectivity and some primary             production, start up was difficult and protracted (Elliot             (1999)). Initial production rates were disappointing (Elliot             (1999)). At least partially, this problem could be due to 2             factors. Initial steam quality at the sand face was poor due             to heat losses to produced fluids. Also, the steam injection             site occurs at the same elevation as production (FIG. 20).             These is no stand-off like SAGD to allow a liquid level to             isolate the producer and prevent steam break through (FIG.             1). Steam by-passing is an issue (Ashok, K. et al, “A             Mechanistic Study of SWSAGD”, SPE, 59333-MS, 2000). Stand             influx problems were another issue (Elliot (1999)). Because             of these issues, an alternative start-up procedure using             cyclic steam has been suggested (Elliot (1999)), but this             has not been field tested.         -   Even after start-up, SWSAGD performance has been             disappointing (Saltuklaroglu (1999), Elliot (1999)). Elan             Energy was the inventor and major operator of SWSAGD. Prior             to late 1999, Elan had drilled 19 SWSAGD wells with 7             separate pilots. By the end of 1999, five of the seven             pilots had been suspended or converted to other processes             due to poor performance (Elliot (1999)). Best results were             for high pressure, low viscosity, heavy oils with some             primary production as foamy oil and no bottom water. This             process is focussed on deep thin pay heavy oil, not bitumen.         -   In 1997, Ranger Oil & Gas acquired Elan (Business Day,             “Ranger Oil . . . deal for Elan Energy”, Sep. 3, 1997). In             1999, Ranger was acquired by Canadian Natural Resources             Limited (CNRL) (CNRL “Ranger Oil agrees to CNRL offer”             1999). Post 1999, there have been no indications of further             SWSAGD developments, particularly none associated with             bitumen.         -   Field testing of SWSAGD can be labelled unsuccessful.     -   (vi) A process has also been suggested using heated, vaporized         solvent to get some advantages of both solvent EOR and thermal         EOR. Similar to SAGD a gas gravity drainage (GD) chamber is         formed containing vaporized solvent gas. The solvent condenses         at the cold bitumen interface releasing its latent heat, similar         to steam. The solvent liquid can then dissolve into bitumen to         further reduce viscosity. The process is called N-Solv         (Braswell, J., “New Heavy Oil Solvent Extraction Pilot to Test         Experimental Process” The journal of Petroleum Technology         Online, Jan. 9, 2012). The process claims reduced environmental         impacts compared to SAGD. A field pilot is expected to start up         in 2013 (Braswell (2012)).     -   But the process has the following concerns:         -   Well configuration similar to SAGD. No/little capital cost             reduction.         -   Proposed test site is for thick bitumen pays, no focus on             thin pay resources.         -   Similar to SAGD. 2D process. No longitudinal flows in             reservoir. Hard to breach barriers.         -   Solvent is costly (more valuable than bitumen). Solvent             losses are a key economic concern.         -   Solvent losses cannot be confirmed or estimated prior to end             of process when solvent inventory recovery is attempted.         -   Productivity may be worse than SAGD.         -   Poor field test results for VAPEX—a similar process (NSolv,             “Developing an In Situ Process . . . ” NSolv website, 2012).         -   Hard to start-up process.     -   (vii) A combustion process, using a toe-to-heel geometry, called         THAI (Toe-to-Heel Air Injection) has also been suggested for         thin pay resources (FIG. 22). The process uses a horizontal well         to collect heated oil 8 and combustion gases 22. A vertical         well, completed near the toe of the horizontal well, injects         compressed air 20. Assuming good high temperature oxidation         (HTO) combustion the process is potentially less costly than         SAGD. The process was developed in the laboratory using physical         models (Greaves, M. et al, “THAI—New Air Injection Technology .         . . ”, SPE 99-15, June, 1995).     -   Petrobank Energy and Resources Ltd, Calgary, Alberta has         purchased and developed proprietary rights to the technology and         is developing a series of field pilots (“THAI” Wikipedia         accessed 2012)). The initial pilot has been operating         since 2006. Recently, Petrobank's reserves consultant dropped         reserves related to THAI because of protracted poor performance         (Energy Inc, “Petrobank suffers setback with THAI”. Mar. 8,         2012).     -   One of the problems with THAI is how to prevent air from         short-circuiting the process and by-passing the reservoir by         entering the production well upstream of the combustion front         (FIG. 22). In the laboratory, the by-pass is prevented by the         formation of a coke plug, in the production well, upstream of         the combustion front. If this plug does not form in a field         test, it is necessary to use a moveable high-temperature packer         or a sliding sleeve. Either of these is a difficult task.     -   Another issue is that lateral growth can be slow. There is         no/little steam to foster lateral growth and the geometry         precludes a lateral flow component. Other problems, noted in the         field tests, included corrosion, sand influx, plugging and         explosions in the production well.     -   Other features/concerns with THAI include the following:         -   Air (not oxygen) is in the injectant oxygen-containing gas.         -   No steam is injected, except for start-up, concurrently with             air (or oxygen).         -   Wet combustion (injection of water) is contemplated but not             yet practiced.         -   There is no separate removal of non-condensable, combustion             gases to vent wells or otherwise. These gases are forced to             be removed by the single horizontal production well (FIG.             22). This can impair liquid production rates.         -   The field experience for THAI is poor (Calgary Herald,             “Petrobank Technology earns Zero Grade”, 2012).         -   The current focus of THAI is on heavy oils, not bitumen (OGJ             (2012))     -   (viii) Another, related combustion process is Combustion         Overhead Gravity Drainage (COGD) also called Combustion Overhead         Split Horizontal (COSH) (FIG. 23). Unlike THAI, this process is         a top-down combustion EOR process. The process includes short         paths for bitumen recovery, drainage to a horizontal production         well, separate overhead vertical injector wells for compressed         air 24 and separate vent gas wells 22 (horizontal or vertical)         for combustion gas removal at the flank of the pattern         boundaries (New Tech. Mag. “Excelsior files patent for ISC         Process”, Sep. 25, 2009) (New Tech. Mag. “Excelsior searching .         . . COGD . . . ” Nov. 20, 2009). The flank gas removal system         promotes lateral growth—a problem for THAI. Also, unlike THAI,         gas and liquid production is separate in the reservoir, the         horizontal production well produces only liquids.     -   But the process has the following features/concerns:         -   The combustion reactions at the bitumen interface are             complex and have not been verified by field tests.         -   There are no current/contemplated field tests for COGD or             COSH.         -   The process contemplated air (not oxygen) injection.         -   The process has extra wells (extra capital expenses)             compared to THAI or SAGD.         -   Focus of the process has been on heavy oil, not bitumen.     -   (ix) Toe-to-Heel Steam Flood (THSF) (FIG. 24) is another thermal         EOR process suggested for thin pay reservoirs (Bagci. A. S. et         al, “Investigation of THSF for heavy oil recovery” Energy         Technology Data Exchange, 21025339, July, 2008). FIG. 55 (PRIOR         ART) also depicts THSF but with a shared injection well.     -   So far, the focus for THSF has been in heavy oils not bitumen         (Fatemi, S. M. et al, “Injection Well-Producer Well Combinations         for Toe-to-Heel Steam Flooding (THSF), SPE 140703-MS, May 2011)         (Fatemi, S. M. et al “Preliminary Considerations on the         application of THSF . . . ”, Chem. Eng. Res. & Design,         November 2011) (U.S. Pat. No. 5,626,193). Compared to         conventional (vertical-well) steam floods, THSF has purported         better stability (i.e. gravity stabilizes the process) and         better recoveries (Turta, A. T. et al, “Preliminary         Considerations on the application of THSF . . . ” SPW,         130444-PA, JCPT, November 2009). A small amount of         non-condensable gas added to the steam was shown to improve         performance (Turta (2009)). But by problems include high costs         of steam and lack of field tests.     -   But once communication is established between the injector well         6 and the producer well 8, there is little pressure differential         to push oil to the producer well, without significant steam         breakthrough to the production well. Thus if steam breakthrough         is avoided, the main mechanism is gravity drainage with         progression of the GD steam chamber from toe-to-heel. The         process is now a GD process not a SF.     -   (x) A single-well version of THSF (SWTHSF) was also identified         with a geometry and process similar to SWSAGD (U.S. Pat. No.         5,626,193). The focus was on thin pay heavy oils, not bitumen,         and insulated tubing was used for the steam injector. The         proposed well trajectory, including the tow-region for steam         injection, was horizontal. But, problems/concerns are similar to         THSF.     -   (xi) We can summarize the currently proposed alternatives for         thin pay bitumen EOR as follows:         -   All of the alternatives have been studies mostly using             mathematical simulation models.         -   There has been little (or no) focus on thin pay bitumen             resources.         -   There has been some focus on thin pay heavy oil resources             (THSF, SWTHSF) with no discussion of bitumen EOR.         -   Some of alternatives have included physical model tests             (e.g. ESSAGD, VAPEX, N-SOLV, THAI . . . ), but again, not             focussed on thin pay bitumen resources.         -   A few of the bitumen alternatives (e.g. ESSAGD, VAPEX,             SWSAGD, THAI . . . ) have been field tested, but not             focussed on thin pay bitumen.         -   Some of the bitumen alternatives are now focussed on heavy             oil applications (not bitumen) (e.g. THAI, VAPEX, SWSAGD . .             . )         -   None of these processes has resulted in any field test or             lab physical-model tests, focussed on thin pay bitumen             resources.         -   Some of the processes are projecting field tests (e.g.             N-SOLV) but again not focussed on thin pays.

Steam Assisted Gravity Drainage with added Oxygen (“SAGDOX”) is an improved thermal EOR process for bitumen recovery. The process may use a geometry similar to SAGD (FIG. 36), but it also has versions with separate wells or segregated sites for oxygen 26 injection and non-condensable vent gas 22 removal (FIGS. 26, 27, 28, 29, 30, 31, 32, 33). The process may be considered as a hybrid SAGD and ISC process. ISC is a process that so far, has shown little application for bitumen recovery. Examples of ISC are depicted in FIGS. 43 and 54 (PRIOR ART).

The objective of SAGDOX is to reduce reservoir energy injection costs, while maintaining good efficiency and productivity. Oxygen combustion produces in situ heat at a rate of about 480 BTU/SCF oxygen, independent of fuel combusted (FIG. 34, Butler (1991)). Combustion temperatures are independent of pressure and they are higher than saturated steam temperatures (FIGS. 4, 56). The higher temperature from combustion vaporizes connate water and refluxes some steam. Steam delivers EOR energy from latent heat released by condensation with a net value, including surface heat recovery, of about 1000 BTU/lb (FIG. 3). Table 2 presents thermal properties of steam+oxygen mixtures. Per unit heat delivered to the reservoir, oxygen volumes are ten times less than steam, and oxygen costs (including capital charges) are one ha to one third the cost of steam.

The recovery mechanisms are more complex for SAGDOX than for SAGD. The combustion zone is contained within the steam-swept zone. Residual bitumen, in the steam-swept zone, is heated, fractionated and pyrolyzed by of combustion gages to provide coke that is the actual fuel for combustion. A gas chamber is formed containing steam combustion gases, vaporized connate water, and other gases (FIG. 35). The large gas chamber can be subdivided into a combustion-swept zone 100, a combustion zone 110, a pyrolysis zone 120, a hot bitumen bank 130, a superheated steam, zone 140 and a saturated steam zone 150 (FIG. 35). Condensed steam drains from the saturated steam zone and from the ceiling and walls of the gas chamber. Hot bitumen drains from the ceiling and walls of the chamber and from the hot bitumen zone at the edge of the combustion front (FIG. 35). Condensed water and hot bitumen 8 are collected by the lower horizontal well and conveyed (or pumped) to the surface (FIG. 36).

Combustion non-condensable gases 22 are collected and removed by vent gas wells or at segregated vent gas sites (FIGS. 36, 31). Process pressures may be controlled (partially) by vent gas production, independent of liquid production rates. Vent has 22 production may also be used to influence direction and rate of gas chamber growth

This intention involves the application of the SAGDOX process to thin pay bitumen reservoirs (i.e. thin pay zones).

SUMMARY OF THE INVENTION

-   -   According to one aspect, them is provided, a process to recover         liquid hydrocarbons, from at least one thin pay zone in a         hydrocarbon bitumen reservoir via a substantially horizontal         production well wherein said hydrocarbon bitumen reservoir         further comprises, a top and a bottom; said process comprising         the use of Steam Assisted Gravity Drainage with Oxygen (SAGDOX)         wherein:     -   i) steam is injected into said hydrocarbon bitumen reservoir         above said substantially horizontal production well;     -   ii) oxygen is injected into said hydrocarbon bitumen reservoir         above said substantially horizontal production well; and     -   iii) liquid hydrocarbon is recovered via gravity drainage into         said substantially horizontal production well.

Preferably, said at least one thin pay zone is segregated from said hydrocarbon reservoir, such that fluid flow is contained within said one thin pay zone.

Preferably, said steam is injected proximate said at least one thin pay zone.

Preferably, said oxygen is injected proximate said at least one thin pay zone.

More preferably both said steam and said oxygen are injected proximate said at least one thin pay zone.

More preferably, said oxygen to said steam are injected into said reservoir, preferably proximate said at least one thin pay zone, a ratio from about 0.05 to 1.00 v/v.

In one embodiment, said horizontal well further comprises a toe section and a heel section. Preferably, said toe section is at a first level in said reservoir and said heel section is at a second level in said reservoir. More preferably said heel section is closer to said bottom and said toe section is closer to said top of said reservoir.

In another embodiment, said SAGDOX has a geometry selected from a Toe-to-Heel SAGDOX (“THSAGDOX”) geometry and a Single Well SAGDOX (“SWSAGDOX”) geometry.

Preferably said at least one thin pay zone has a thickness of less than about 25 metres. More preferably said at least one thin pay zone has a thickness of less than about 15 metres.

Preferably the substantially horizontal production well is used to produce water and liquid hydrocarbons and is completed within 2 metres of the reservoir bottom.

Preferably the steam is injected within 20. metres from the substantially horizontal production well, and the oxygen is injected within 50 metres from the substantially horizontal production well; wherein, said substantially horizontal, production well further comprises at least one a perforation zone less than 50 metres in length.

In one embodiment, the injection of oxygen and steam is controlled in the range from 0.05 to 1.00 (v/v) oxygen:steam ratio.

Preferably the ratio of oxygen to steam is increased during the process so that the oxygen/steam ratio (v/v) is maximized proximate the end of the process.

In another embodiment, said THSAGDOX further comprises an uplifted toe section in said substantially horizontal production well.

According to one aspect, there is provided a process to recover liquid hydrocarbons, from a hydrocarbon bitumen reservoir, via a substantially horizontal production well, wherein said hydrocarbon bitumen reservoir has at least one thin pay zone, a top, and a bottom preferably at least one thin pay bitumen containing zone of less than about 25 metres thickness; said process comprising Steam Assisted Gravity Drainage with Oxygen (SAGDOX) selected from the group consisting of Toe-to Heel SAGDOX (THSAGDOX) and Single Well SAGDOX (SWSAGDOX).

In one embodiment, said substantially horizontal well further comprises a toe section and a heel section. Preferably said toe section is at a first level in said reservoir and said heel section is at a second level in said reservoir. Preferably said heel section is closer to said bottom and said toe section is closer to said top.

In one embodiment said SAGDOX is THSAGDOX, more preferably said THSAGDOX further comprises said horizontal well with an uplifted toe section.

In another embodiment said SAGDOX is SWSAGDOX.

In one embodiment, the horizontal production well is completed within about 2 metres of the bottom.

In another embodiment, steam is injected proximate said horizontal production well via at least one steam injector, preferably within about 20 metres from the horizontal production well.

In another embodiment, oxygen, preferably oxygen containing gas is injected proximate said horizontal productions well via at least one oxygen injector, preferably within about 50 metres from the horizontal production well and more preferably with a perforation (contact) zone less than about 50 metres in length.

In another embodiment, a ratio of oxygen to steam, is controlled in the range from about 0.05 to 1.00 (v/v).

In another embodiment, non-condensable gases produced by combustion and inert gases in the oxygen (vent gas) are removed by at least one vent gas outlet, preferably separately removed. Most preferably separately removed from about 5 to about 75 metres from the horizontal production well.

In another embodiment, said at least one steam injector and said at least one oxygen injector is separated from said at least one vent gas outlet by at least about 100 metres.

In another embodiment, the reservoir is slanted and the horizontal production well is less than about 2 metres from the bottom of the reservoir at its closest point.

In another embodiment, the at least one steam injector and the at least one oxygen containing gas injector is within 10 metres of the horizontal production well.

In another embodiment, said steam is injected into said reservoir using at least one parallel horizontal steam injection well in a plane substantially vertical to the horizontal production well, preferably from about 3 about 8 metres above the horizontal production well.

In another embodiment, said steam is injected using at least one single substantially vertical well, preferably a plurality of substantially vertical wells.

In another embodiment, oxygen containing gas is injected into the reservoir using at least one single substantially vertical well, preferably a plurality of substantially vertical wells.

In another embodiment, vent gas is removed from the reservoir using at least one single substantially vertical well, preferably a plurality of substantially vertical wells.

In another embodiment, said steam and oxygen containing gas are comingled, preferably at the surface, and, injected into the reservoir using at least one single substantially vertical well, preferably a plurality of substantially vertical wells.

In another embodiment, said steam and oxygen containing gas are substantially segregated preferably by at least one packer, more preferably by a plurality of packers, and injected separately into the reservoir, preferably by at least one single substantially vertical well, more preferably by a plurality of substantially vertical wells.

In another embodiment, said steam and oxygen containing gas are substantially segregated using concentric tubing and packers, preferably with steam in the central tubing surrounded by oxygen containing gas in an adjacent annulus, and with oxygen containing gas injected at an elevation in the reservoir higher than said steam injected elevation.

In another embodiment, a single substantially vertical well is used to inject steam and oxygen containing gas into said reservoir, where the single substantially vertical well is completed within about 50 metres from the toe of the horizontal production well.

In another embodiment, the oxygen containing gas injection is accomplished using as segregated toe section of the horizontal production well.

In another embodiment, the vent gas removal site is a segregated annulus section in the heel rise section of the horizontal well.

In another embodiment, said steam and oxygen containing gas are comingled at the surface and injected into the reservoir using a segregated toe section of the horizontal well.

In another embodiment, said oxygen containing gas and steam are substantially segregated and simultaneously injected into the reservoir from a segregated toe section of the horizontal well.

Preferably said oxygen containing gas and steam are substantially segregated by using concentric tubing and packers, said concentric tubing further comprising central tubing and an adjacent annulus, with steam in the central tubing surrounded by oxygen-containing gas in the adjacent annulus.

In another embodiment, said vent gas is removed in a segregated annulus in the heel rise section of the horizontal well.

In another embodiment, the toe of the horizontal production well is drilled upwards and completed so the lowest injection orifice (for injection of at least one of steam; oxygen, containing gas and both) is greater than 2 metres higher than the horizontal plane of the horizontal section of the horizontal production well.

In another embodiment, the horizontal production well is drilled parallel to the reservoir bottom in an up-dip direction in a slanted reservoir, so that the lowest injection orifice is more than 2 metres higher in elevation than the highest liquid production orifice.

In a preferred embodiment, the ratio of oxygen, in oxygen containing gas, to steam is increased during the maturation of the process so that the oxygen to steam ratio (v/v) is maximized at the end of the process life.

In a preferred embodiment, an extender tube proximate the toe of the horizontal production well is used, preferably to ensure that the lowest pressure in the production well is proximate the toe.

Preferably said vent gas wells (sites) and steam/oxygen injectors are separated by at least 100 metres.

In one embodiment, the oxygen containing gas is oxygen with an oxygen content of 95 to 99.9 (v/v) percent.

In another embodiment, the oxygen containing gas is air, preferably enriched air, with an oxygen content of 21 to 95 (v/v) percent.

In one embodiment the hydrocarbon liquid is bitumen (API density <10; in situ viscosity >100,000 cp.).

In another embodiment the hydrocarbon liquid is heavy oil (10<API<20; in situ viscosity 1000 cp.)

In one embodiment, the substantially horizontal production well has a length greater than 1000 metres.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 depicts a traditional SAGD geometry

FIG. 2 depicts a pattern end view of a SAGD life cycle

FIG. 3 depicts saturated steam properties

FIG. 4 depicts Pressure versus Temperature for Saturated Steam

FIG. 5 depicts bitumen Viscosity versus Temperature of Long Lake bitumen

FIG. 6 depicts the Gravdrain Equation for SAGD Bitumen Productivity

FIG. 7 depicts fractional residual bitumen in pores versus saturated steam temperature and equivalent hydrostatic depth for residual bitumen in steam-swept zones

FIG. 8 depicts SAGD hydraulic limitations

FIG. 9 depicts the Top of the McMurray Formation

FIG. 10 depicts the Thickness of the McMurray Formation

FIG. 11 depicts the Porosity Interval of the McMurray Formation

FIG. 12 depicts the Bitumen Pay Thickness of the McMurray Formation

FIG. 13 depicts the API Gravity of the McMurray Formation

FIG. 14 depicts a Traditional SAGD Recovery Geometry

FIG. 15 depicts a first SAGD geometry for recovery in a thin pay zone

FIG. 16 depicts a second SAGD geometry for recovery in a thin pay zone

FIG. 17 depicts a third SAGD geometry for recovery in a thin pay zone

FIG. 18 depicts a simple SAGD model

FIG. 19 depicts unrecovered bitumen at end of life processing versus net pay thickness

FIG. 20 depicts a SWSAGD schematic and well configuration (with packers)

FIG. 21 depicts a SWSAGD schematic and well configuration (without packers)

FIG. 22 depicts a THAI geometry for ISC

FIG. 23 depicts a COGD/COSH geometry for ISC

FIG. 24 depicts a typical SAGDOX geometry according to the present invention

FIG. 25 depicts SWSF geometries for SWSAGD, SWSAGDOX, SWSF(U) and SWSAGDOX(U)

FIG. 26 depicts a first embodiment of a THSAGDOX according to the present invention

FIG. 27 depicts a second embodiment of a THSAGDOX according to the present invention

FIG. 28 depicts a third embodiment of a THSAGDOX according to the present invention

FIG. 29 depicts a fourth embodiment of a THSAGDOX configuration and piping schematic according to the present invention

FIG. 30 depicts an embodiment of a SWSAGDOX configuration according to the present invention

FIG. 31A depicts an embodiment of a SWSAGDOX with centralized packers with steam and oxygen being premixed, according to the present invention.

FIG. 31B depicts an embodiment of a SWSAGDOX with centralized packers with steam and oxygen being segregated, according to the present invention.

FIG. 31C depicts an embodiment of a SWSAGDOX with centralized packers with steam and oxygen being segregated and isolated, according to the present invention.

FIG. 31D depicts an embodiment of a SWSAGDOX with centralized packers, steam and oxygen mixed, and a bitumen pump, according to the present invention.

FIG. 31E depicts an embodiment of a SWSAGDOX with centralized packers with steam and oxygen segregated, and a bitumen pump, according to the present invention.

FIG. 32 depicts an embodiment of a SWSAGDOX(U) schematic and associated piping schematic according to the present invention

FIG. 33 depicts a second embodiment of a SWSAGDOX(U) schematic and associated piping schematic according to the present invention

FIG. 34 depicts HHV versus H/C ratio of fuel

FIG. 35 depicts typical SAGDOX process mechanisms

FIG. 36 depicts a typical THSF

FIG. 37 depicts ISC minimum air flux rates

FIG. 38 depicts Steam and Oxygen Combustion Tube Tests II

FIG. 39A depicts a SAGDOX geometry according to the present invention.

FIG. 39B depicts a SAGDOX geometry (THSAGDOX) according to the present invention.

FIG. 39C depicts a SAGDOX geometry (SWSAGDOX) according to the present invention.

FIG. 40 depicts a multiple well THSAGDOX geometry with initial steam and oxygen injection at the toe of the production well according to the present invention

FIG. 41 depicts a multiple well THSAGDOX geometry with initial steam and oxygen injection at the middle of the production well according to the present invention

FIG. 42 depicts the recovery pattern of a gas chamber during various stages of THSAGDOX

FIG. 43 depicts a conventional ISC

FIG. 44 depicts a multiple well THSAGDOX geometry with alternating oxygen/steam and vent gas wells according to the present invention

FIG. 45 depicts SWSAGDOX and SWSAGDDOX(U) hydraulic limitations

FIG. 46 depicts a typical SWSAGD(U) schematic and associated piping schematic

FIG. 47 depicts oxygen pipe and tubing design

FIG. 48 depicts an embodiment of a THSAGDOX with a shared injection well for oxygen and steam according to the present invention

FIG. 49 depicts an embodiment of a SWSAGDOX geometry in a tilted thin pay zone according to the present invention

FIG. 50 depicts a THSAGDOX liquid drawdown at the heel and toe of the production well

FIG. 51 depicts a SWSAGD in tilted pay zones

FIG. 52 depicts SWSAGD in tilted pay zones

FIG. 53 depicts TH geometries for THSF, THISC (or THAI) and THSAGDOX

FIG. 54 depicts SWISC process

FIG. 55 depicts a THSF with a shared injection well

FIG. 56 depicts Steam and Oxygen Combustion Tube tests I

FIG. 57 depicts a three well THSAGDOX geometry according to the present invention

DETAILED DESCRIPTION OF THE INVENTION

Preferred parameters in SAGDOX geometries of the present invention in thin pay zones include the following:

-   -   (1) Use Oxygen (rather than air) as the oxidant injected         -   If the cost of treating vent gas to remove sulphur             components and to recover volatile hydrocarbons is factored             in, even at low pressures the all-in cost of oxygen is less             than the cost of compressed air, per unit energy delivered             to the reservoir.         -   Oxygen occupies about one fifth the volume compared to air             for the same energy delivery. Well pipes/tubing is smaller             and oxygen can be transported further distances from a             central plant site.         -   In situ combustion (ISC) using oxygen produces mostly             non-condensable CO₂, undiluted with nitrogen, CO₂ can             dissolve in bitumen to improve productivity. Dissolution is             maximized using oxygen.         -   Vent gas, using oxygen, is mostly CO₂ and may be used for             sequestration.         -   There is a minimum oxygen flux to sustain HTO combustion             (FIG. 37)         -   It is easier to attain/sustain this flux using oxygen     -   (2) Keep oxygen injection at a concentrated site         -   Because of the minimum O₂ flux constraint from in situ             combustion (FIG. 37), the oxygen injection well (or a             segregated section) should have no more than 50 metres of             contact with the reservoir.     -   (3) Segregate Oxygen and steam injectants, as much as possible         -   Condensed steam (hot water) and oxygen are very corrosive to             carbon steel.         -   To minimize corrosion, either 1) oxygen 26 and steam 6 are             injected separately (FIGS. 36, 26); 2) comingled steam 6 and             oxygen 26 have limited exposure to a section of pipe that             can be a corrosion resistant alloy; 3) the section integrity             is not critical to the process (FIG. 31(b); or 4) the entire             injection string is a corrosion resistant alloy (FIG.             31(a)).     -   (4) The vent gas well (or site) is near the top of the         reservoir, far from the oxygen injection site.         -   Because of steam movement and condensation, non-condensable             gas concentrates near the top of the gas chamber.         -   The vent gas well should be far from the oxygen injector to             allow time/space for combustion.     -   (5) Vent gas should not be produced with significant oxygen         content         -   To mitigate explosions and to foster good oxygen             utilization, any vent gas production with oxygen content             greater than 5% (v/v) should be shut in.     -   (6) Attain/retain a minimum amount of steam in the reservoir         -   Steam is added/injected with oxygen in SAGDOX because steam             helps combustion. It preheats the reservoir so ignition, for             HTO, can be spontaneous. It adds OH⁻ and H⁺ radicals the             combustion zone to improve and stabilize combustion (FIGS.             56 and 38, Moore (1994)). This is also confirmed by the             operation of smokeless flares, where steam is added to             improve combustion and reduce smoke (Stone (2012), EPA             (2012), Shore (1996)). The process to gasify fuel also adds             steam to the partial combustor to minimize soot production             (Berkowitz (1997)).         -   Steam also condenses and produces water that “covers” the             horizontal production well and isolates it from gas or steam             intrusion.         -   Steam condensate adds water to the production well to             improve flow performance—water/bitumen emulsions—compared to             bitumen alone.         -   Steam is also a superior heat transfer agent in the             reservoir. When one compares hot combustion gases (mostly             CO₂) to steam, the heat transfer advantages of steam are             evident. For example, if one has a hot gas chamber at about             200° C. at the edges, the heat available from cooling             combustion gases from 500° C. to 200° C. is about 16             BTU/SCF. The same volume of saturated steam contains 39             BTU/SCF of latent heat—more than twice the energy content of             combustion gases. In addition, when hot combustion gases             cool, they become effective insulators impeding further heat             transfer. When steam condenses to deliver latent heat, it             creates a transient low-pressure that draws in more steam—a             heat pump, without the plumbing. The kinetics also favour             steam/water. The heat conductivity of combustion gas is             about 0.31 (mW/cmK) compared to the heat conductivity of             water of about 6.8 (mW/cmK)—a factor of 20 higher. As a             result of these factors, combustion (without steam) has             issues of slow heat transfer and poor lateral growth. These             issues may be mitigated by steam injection.         -   Since one can't measure the amount of steam in the             reservoir, SAGDOX sets a steam minimum by a maximum             oxygen/steam (v/v) ratio of 1.0 or alternately 50% (v/v)             oxygen in the steam and oxygen mix.     -   (7) Attain (or exceed) a minimum oxygen injection         -   Below about 5% (v/v) oxygen in the steam and oxygen mix, the             combustion swept zone is small and the cost advantages of             oxygen are minimal. At this level, only about a third of the             energy injected is due to combustion.     -   (8) Maximum oxygen injection         -   Within the constraints of (6) and (7) above, because per             unit energy oxygen is less costly than steam, the             lowest-cost option to produce bitumen is to maximize             oxygen/steam ratios.     -   (9) Use preferred SAGDOX geometries         -   Depending on the individual application, reservoir matrix             properties, reservoir fluid properties, depth, net pay,             pressure and location factors, there are three preferred             geometries for SAGDOX (FIG. 39a-c ).         -   39 b (THSAGDOX) and 39 c (SWSAGDOX) are most preferred for             thinner pay resources, with only one horizontal well             required. Compared to SAGD, THSAGDOX and SWSAGDOX have a             reduced well count and lower drilling costs. Also, internal             tubulars and packers should be usable for multiple             applications.     -   (10) Control/operate SAGDOX by:         -   (i) Sub-cool control on fluid production rates where             produced fluid temperature is compared to saturated steam             temperature at reservoir pressure. This assumes that gases,             immediately above the liquid/gas interface, are             predominantly steam.         -   (ii) Adjust oxygen/steam ratios (v/v) to meet a target             ratio, subject to a range limit of 0.05 to 1.00         -   (iii) Adjust vent gas removal rates so that the gases are             predominantly non-condensable gases, oxygen cement is less             than 5.0% (v/v), and to attain/maintain pressure targets.         -   (iv) Adjust steam and oxygen injection rates (subject             to (ii) above), along with (iii) above, to attain/maintain             pressure targets.

THSAGDOX

Although SAGDOX may also be used for thin pay bitumen recovery, the twin horizontal wells (FIG. 36) are difficult to fit within the thin pay resource limits, the well count is increased compared to SAGD the capital expenses are also increased.

THSAGDOX (Toe-to-Heel SAGDOX) is a preferred version of SAGDOX that can be applicable to thin pay EOR., using a mixture of steam 6 and oxygen 26 to supply energy rather than steam alone. The horizontal liquid-production well of SAGDOX (and SAGD) is retained so that bitumen drainage can be accomplished in short path lengths. Steam is much more mobile than heated bitumen, so the horizontal steam injection of SAGDOX or SAGD is replaced by a vertical well injecting steam 6 and oxygen 26, where oxygen 26 is preferably injected near the top of the pay zone. Vent gas 22 (non-condensable combustion gas) is removed either through a separate vertical well or wells, or in a segregated portion (annulus) near the vertical section of the horizontal production well. Vent gas 22 removal is preferably conducted near the top of the net pay zone.

The vertical oxygen/steam injector well is designed to 1) segregate steam 6 and oxygen 26 to minimize corrosion and 2) preferably inject oxygen 26 proximate the top of the pay zone and steam 6 proximate the lower region in the pay zone. This has the added benefit that oxygen gas 6 in the annulus, around a steam injector tubing, is a good heat insulator and this will prevent/minimize heat losses from steam to the overburden, as steam is conveyed from the well head to the reservoir.

FIGS. 26, 27, 28, 40, and 57 show schematics for various THSAGDOX process schemes. FIG. 29 shows a piping schematic that can apply to all of these process types.

The process is started by circulating steam 6 in the production horizontal well and by cycling steam 6 (huff-and-puff) in the vertical wells until the wells communicate with each other (i.e. fluids flow from one well to another). After communication is established, wells are converted to THSAGDOX operation with steam 6 and oxygen 26 injection and water/bitumen 8 and vent gas 22 production.

The THSAGDOX horizontal production well may be longer than a SAGD well for the same bitumen productivity, because there is less water flowing in the well. FIGS. 40, 41, and 57 show multiple vertical well versions of THSAGDOX to facilitate longer horizontal wells or easier start-up and operation of shorter wells. Separate vertical wells close to the toe steam/oxygen injector wells are initially used to vent as removal wells and subsequently, converted to steam/oxygen injectors as the combustion front moves from near the toe of the horizontal well toward the heal of the horizontal well (FIG. 42). This enables fast start-up and improved conformance during the maturation of the process.

Another version of this scheme starts the combustion near the mid point of the horizontal well, with the combustion front moving both toward the toe and heel of the horizontal production well (FIG. 41).

Feature of these THSAGDOX process schemes include the following:

-   -   Separation is retained between 0₂ injection and vent gas         removal. Vent gas wells may be used to control conformance of         the ISC process part of THSAGDOX.     -   The process adds a 3D component mechanism (flooding) with         longitudinal reservoir flows forced by the geometry.     -   The process may reduce the capital cost of wells by reducing         well count, reducing well length, using vertical rather than         horizontal wells, or by reducing the size (diameter) of wells.     -   The process reduces operating costs. Oxygen is less costly than         steam per unit energy delivered to the reservoir.     -   The process may use a tapered oxygen strategy, where oxygen         concentration is increased during the life of the projects to         reduce costs, extend useful project life and increase bitumen         recovery.     -   The process may use a pump, in the horizontal well, if necessary         to help produce bitumen and water.     -   The process will produce extra water compared to steam         injection. Connate water will be vaporized in the combustion         swept zone (FIG. 35). Water is also produced as a product of         combustion. Depending on leakage or retention rates in the         reservoir, THSAGDOX will likely produce more water than it         injects as steam.     -   Hot combustion gases will reflux some water to maintain a good         water/steam inventory in the reservoir.     -   The process also retains all of the SAGDOX benefits.     -   Carbon dioxide produced as a combustion product is concentrated         in vent gas (or dissolved/concentrated in liquid product stream)         and should be suitable for sequestration.     -   Oxygen may be economically pipelined from a distant site without         energy losses.     -   Water produced from steam injection may help isolate the         horizontal production well and minimize non-condensable gas         intrusion into this well.     -   The vertical well used for oxygen and steam injection may         minimize heat losses if steam is in the inner tube and oxygen is         in the annulus. Oxygen gas is a good insulator to retain heat in         the steam. It is preferable that steam injection is in the         central tube and oxygen surrounds steam as an insulator (FIG.         29).

It may be suggested that conversion of THSAGDOX to a pure combustion (ISC) EOR process is appropriate particularly for this reason because oxygen is less costly than steam as a source of energy to heat up reservoir bitumen. But, retention of steam as injectant is desirable because:

-   -   Steam stabilizes combustion and improves combustion kinetics     -   Steam preheats combustion zones     -   Steam acts as a good heat transfer medium—better than hot         combustion gases (heat pump effect)     -   Steam can effect lateral growth (a problem with some ISC         processes)     -   Steam, when condensed, can help cover/seal the production well         and inhibit non-condensable as break through to the well     -   Steam/water can be refluxed by hot combustion products     -   In the production well, water/bitumen mixtures have lower         viscosities than bitumen by itself.     -   Steam injection increases the size of the steam-swept zone to         help ensure that combustion is focussed on residual bitumen         (coke)     -   Steam creates flow paths for combustion.

It may also be suggested that water injection, not steam, is a better way to produce steam in the reservoir and improve energy efficiency. Water may scavenge heat from the combustion swept zone (FIG. 35) to produce steam in situ, rather than using the on the surface to produce steam in a boiler. This was the preferred way to accomplish wet combustion using vertical injector/producer wells (FIG. 43). But, this is not a good idea using Steam Flood with Oxygen in Thin Pay Reservoirs (SFOXT) geometries for the following reasons:

-   -   In SAGDOX geometry compared to ISC geometry (FIG. 43), flow         paths from injector to producer are very short. If water were         injected, using a vertical injector (FIG. 29) it would easily         by-pass the process and flow directly to the production well.     -   Alternately if the combustion front is close to the injector,         water could quench combustion and cause low temperature         oxidation (LTO) to start.

It may be suggested that because the hot zone in THSAGDOX is localized to the oxygen 26 injection zone and then proceeds toward the toe of the horizontal well (FIG. 42), that the bitumen production rate for THSAGDOX can be expected to be less than SAGD, where the steam chamber grows along the length of the horizontal producer at the same time (FIG. 2). THSAGDOX compensates for this by producing heat at a higher temperature than steam, by using steam 6 as a heat transfer agent and by refluxing some steam. This may also be improved by using multiple oxygen 26 injection sites (FIG. 44) so that combustion can be spread out along the well and multiple combustion sites will grow simultaneously.

Because there is less fluid in a THSAGDOX horizontal well compared to a SAGD horizontal well due to less water produced per barrel of bitumen, for the same pressure drop a THSAGDOX horizontal well can be much longer than a same-size SAGD horizontal well (up to about 2500 metres), depending on the oxygen level in the injectant oases

SWSAGDOX

THSAGDOX is better than SAGD for thin pay bitumen EOR because of the reduction in well count and cost (1 horizontal+1 vertical, were the vertical well can be shared between patterns) compared to SAGD (2 horizontal wells) and a reduction in energy costs by using oxygen gas for combustion. As pay thickness decreases, THSAGDOX capital expenses may be too much to justify bitumen EOR.

Another version of SAGDOX called SWSAGDOX (Single Well SAGDOX) may cut costs even more. The process uses a single horizontal well to effect the SAGDOX process. Portions of the well are segregated for steam 6 and oxygen 26 injection and for bitumen/water 8 and vent gas 22 production, using concentric tubing and segregation packers 18 (FIGS. 30 and 31 a-e). Capital expenses are lowered both by reducing the well count (to 1) and by potential retrieval and reuse of various completion components (packers and tubing).

The simplest version of SWSAGDOX is shown in FIG. 31(a), where steam and oxygen 30 are mixed at surface and injected premixed, rather than relying on mixing in the reservoir. To resist corrosion, the injection tubing 30 for the oxygen and steam mixture would be an alloy-steel or another corrosion-resistant material. An alternate scheme, to obviate corrosion, is to superheat the oxygen+steam mixture 30 to prevent steam condensation on the injectant tubular walls. Heat losses, particularly for deep thin pay bitumen reservoirs, from this mixture may be an issue. The toe of the horizontal well 40 (FIG. 31(a)) is also exposed to oxygen+water corrosion. But, the integrity of the toe region of this well is not critical to the EOR process.

An improvement on this design (FIG. 31(b)) uses tubing to segregate oxygen and steam 30, with oxygen 26 surrounding the steam injector tube. The oxygen gas 26 acts as a good insulator for the steam tube and reduces heat losses to preserve steam quality. But, the toe region of the horizontal well 40 is still exposed to steam+oxygen corrosion.

Yet another improvement is shown in FIG. 31(c) where a packer 18 used to segregate oxygen and steam 30 prior to entering the reservoir. This can minimize toe corrosion and still insulate the steam line to reduce heat losses.

Yet another embodiment is to complete the horizontal well using a corrosion resistant material, at least for the toe section of the well.

Another issue for SWSAGDOX. (FIG. 30, 31 a-e) is that steam injection is at the same (horizontal) level as liquid petroleum. SAGD prevents steam breakthrough to the producer or flooding of the steam injector, by completing the producer injector with an offset spacing of about 5 metres (FIG. 1) and controlling the process with a steam/liquid interface between the injector and producer (FIG. 8). The interface is tilted by the pressure drop in the producer, but with good operation prevents steam by-pass and flooding of the injector. The highest point of the interface is at the toe of the horizontal wells.

This sub-cool strategy can be retained by SAGDOX and THSAGDOX injection of steam (and oxygen) above the plane of the horizontal production well.

However, in SWSAGDOX (FIG. 45), if the steam 6+oxygen 26 section is flat, and one operates the process so that liquid covers the production section to obviate steam 6+oxygen 26 break through, the end of the horizontal well will be flooded. This will inhibit steam 6+oxygen 26 injection and harm conformance. If one produces liquid at a faster rate to remove this problem, the entire production section will be open to steam 6 and oxygen 26 breakthrough.

The solution shown at the bottom of FIG. 45 and in FIGS. 25, 32, 33, and 46 is to drill and complete the horizontal well so the toe section is slanted upwards to near the top of the pay zone. This enables one to retain liquid covering the horizontal production section so that oxygen 26 and steam 6 don't break through to the producer well and to have oxygen 26 and steam 6 injection above the liquid interface 12 so the injection is not flooded (FIG. 45). The process for such a geometry is termed SWSAGDOX(U) where U denotes uplift of the toe region of the horizontal well. This is a preferred geometry for SWSAGDOX.

SWSAGDOX process has the advantages of THSAGDOX processes, with the following additional features:

-   -   The horizontal well interior tubing can be retrieved and reused         so that its cost can be spread amongst several process units.     -   This is the least cost option (capital expenses) for thin pay         steam+oxygen EOR     -   This is the least well-count option     -   The process has longitudinal flows with a drive recovery         mechanism     -   The production segment of the well can be isolated by fluid         production if the well is drilled updip or if the toe portion of         the well is drilled upward     -   If a pump is necessary, it can be accommodated (e.g. FIG. 31(a))     -   The design retains separate vent gas removal     -   If steam 6 occupies the central injection tube, oxygen gas 26         can help insulate the steam tube and minimize heat losses (FIGS.         31a-e )     -   The SWSAGDOX (U) version of the process allows liquids to cover         the horizontal production section to prevent or inhibit gas         breakthrough (steam, oxygen, combustion gases) and, at the same         time, the gas injection zone (steam+oxygen) is not flooded by         the liquids.

The geometry of SWSAGDOX (FIG. 30) is similar to the geometry for the SWSAGD (FIG. 20), but with the following process distinctions:

-   -   SWSAGDOX uses steam+oxygen injection. SWSAGD uses steam only     -   SWSAGD injects steam at the same elevation as production. A         preferred version of SWSAGDOX (FIG. 32), injects steam and         oxygen at higher elevation than liquid production.     -   SWSAGD has had disappointing field tests.     -   SWSAGD was focused on heavy oil EOR, not bitumen.     -   SWSAGD was concerned by heat leakage from steam injectors to         produced fluids and spurred development of insulated tubing for         steam injection. SWSAGDOX insulates the steam tubing using         oxygen in the annulus (FIG. 31B).     -   Because oxygen has about 10 times the energy density as steam,         piping for SWSAGDOX can be much smaller than piping for SWSAGD.     -   SWSAGD is a saturated steam process. Temperatures are limited by         the properties of saturated steam. At the same pressure,         SWSAGDOX will operate at higher T than SWSAGD.

An important issue for SAGDOX and SWSAGDOX is to isolate various zone using packers that are operable at high temperatures. This is an active area of development for oil suppliers (Haliburton, “Zonal Isolation for Steam Injection . . . ” website, May 2012) (Schlumberger, “Packer Systems”, website, May 2012). It is also of particular concern in the Geothermal industry, where conditions may be more severe and corrosive than for EOR (DOE “Enhanced Geothermal Systems Wellfield Construction Workshop” San Francisco, Oct. 16, 2007). Small, self-sealing packers are also being developed for smaller well sizes (OGJ “Self-Setting Thermal Packers Help Cyclic Steam” 1998).

Current technology (˜2012) is available for thermal packers for larger pipe sizes and up to 600° F. (316° C.) (Haliburton (2012)) and for small tubing packers up to 400° C. (OGJ (1998)). The pressure seals are rated for pressures exceeding expectations for SAGDOX and SWSAGDOX processes. Most packers are retrievable and can be used many times. The small tubing packers have been operated in the field for up to 5000 pressure cycles/yr. (OGJ (1998)).

Thermal packers for SAGDOX and SWSAGDOX processes are conventional technology, currently available.

SAGDOX and related processes (THSAGDOX, SWSAGDOX, SWSAGDOX(U)) can have a higher well count than SAGD, depending on process design. This can be partially (or totally) offset by reduced pipe sizes using SAGDOX. Pipe size reductions are due to 2 factors—oxygen contains about 10 times the energy content compared to steam (Table 2); also because SAGDOX injects less steam than SAGD for the same energy injection rate, the production fluids (water+bitumen) can be less than SAGD fluids for the same bitumen production rate.

Assuming the following pipe design criteria for a shallow SAGD project:

-   -   (i) 500 bbls/d bitumen productivity.     -   (ii) 1 MMBTU energy demand per bbl bitumen (SOR˜3)     -   (iii) Steam at 1000 BTU/lb. heat content.     -   (iv) 100 psia, 160° C. steam injection (50 m depth hydrostatic         pressure (FIG. 4))     -   (v) 25 ft/sec. design for steam injection     -   (vi) 1 ft/sec. for liquid (water+bitumen) production     -   (vii) all steam injected is produced as hot water

One can then calculate for a SAGD project, that steam demand is 500,000 lb/day=1428.6 bbls/day=28.57 CF/sec, at reservoir conditions. Using the design criteria above, the steam injector pipe has a diameter of 7.23 inches and production tubing has a diameter of 4.79 inches.

Applying this to SAGDOX-related projects for the same conditions, FIG. 47 shows pipeline velocity limits for oxygen delivery design, using carbon steel or stainless steel pipes, where potential particulate impingement is the design limit—the worst case (Asia Industrial Gases Association “Oxygen Pipeline Systems” 2005). One may assume the following, in addition to the above:

(i) 100 ft/sec oxygen velocity design, at downhole conditions (FIG. 47)

-   -   (ii) Use a SAGDOX (35) mixture, 35% oxygen (v/v) in a steam         oxygen mix; 84.5% of heat injected comes from oxygen combustion         (Table 2)

One can then calculate pipe sizes for oxygen and steam delivered in separate pipes. The oxygen demand is 880 MSCFD=3.36 tonnes/day.

The steam demand drops to 77,500 lbs/day=221 bbls/day=4.18 cf/sec, at reservoir conditions. The pipe size for oxygen injection is 2.09 inches in diameter. The pipe size for steam injection is 2.76 inches in diameter.

If the steam and oxygen are conveyed in a single pipe (FIGS. 26, 27, 29), the total pipe size needed is 3.47 inches (ignoring wall thickness).

The production well is also downsized, because less steam is injected and water produced. The calculated well size is 2.93 inches, in diameter.

SAGDOX-related processes also must produce vent gases. The vent gas volumes are similar to the oxygen injection volumes, with the same size pipe requirements (2.09 inches, in diameter)

It is often assumed, for pipelines, that capital expense is proportional to pipe diameters or to cumulative pipe diameters for multiple piping. One can do the same here, as follows:

total D inches % SAGD (eg. FIG. 1) 12.02 100 SAGDOX with separate wells for 9.87 82 all streams (e.g. FIG. 36) SWSAGDOX with all fluids 5.00 42 contained in a single well. (Single well D only, eg. FIG. 30, 31)

The SAGDOX versions all have less total pipe diameter. All SWSAGDOX pipes could be retained in a single 5″ pipe (not accounting for pipe wall thickness).

The preferred embodiments of THSAGDOX and SWSAGDOX of the present invention depend on the nature of the target reservoir—specifically the reservoir thickness, the reservoir continuity, the reservoir quality and the reservoir depth. The preferred version for SWSAGDOX is SWSAGDOX(U) with the up-lifted toe region.

There are 3 versions of THSAGDOX to consider:

-   -   (i) The simple version (FIG. 26) with a single vertical injector         well for oxygen 26 and steam 6 completed near the toe of the         horizontal producer and vent gas 22 removal accomplished using a         segregated portion of the horizontal well completed near the top         of the pay zone. The piping/tubing is simple with oxygen 26         delivered in the annulus to insulate the steam tube and to         minimize heat losses. The production well, with vent gas 22         removal retains the option to use submersible pumps if necessary         (FIG. 29). This system can best be applied for deposits (10 to         25 metre thickness) preferably segregated from said reservoir,         relatively unimpaired reservoirs (little/no shales, lean zones),         and for moderate continuity (well lengths 500-1000 metres).     -   (ii) If a similar more extensive and unimpaired reservoir is         present, one can have adjacent patterns and the patterns can         share vertical wells, a scheme such as FIG. 36 can share         separate vent wells. This is not too costly and offers the         prospect of conformance control using the separate vent wells.         Another version, show in FIG. 48, allows for sharing of vertical         injection wells, to reduce costs,     -   (iii) If a similar deposit (10 to 25 metre thickness) is present         but we expect some reservoir impairments, resulting in lower         productivity expectations, it is preferred to consider longer         horizontal wells with multiple injection/vent wells, where the         injection/vent wells can be converted from injection to vent         uses (and vice versa) depending on performance (FIGS. 40, 41,         57). This gives, added flexibility for conformance control and         performance control and production management in cases where the         reservoir is impaired or may be impaired. Productivity need not         suffer because we can use multiple injectors simultaneously         (FIG. 44) and drill longer horizontal wells than SAGD (500-2500         metres).

Because of reduced well count and reusable completion components (tubing, packers), the thinnest reservoirs (5-15 metres) are best exploited using SWSAGDOX(U) process shown in FIGS. 30, 31 a-e, 32, 33, 49. The process doesn't lend itself to well sharing (no vertical wells), but the capital expenses should be minimized.

One also has the choice for THSAGDOX, where one draws down liquids from the horizontal well. The conventional choice draws liquids from the heel region of the horizontal producer. But, one can also draw from the toe using a pipe extender (FIG. 29). The advantage of toe down is illustrated in FIG. 50. One can prevent the steam injector portion of the vertical injector well from being flooded by the liquid interface.

(1) Distinctions of THSAGDOX Compared to THAI (FIG. 53)

-   -   THSAGDOX removes vent gases using separate wells or segregated         zones. THAI forces vent gases to be produced in the horizontal         production well.     -   THSAGDOX operates on a gravity drainage process. Pressure         differentials between gas injection and liquid product are very         small. THAI operates as a flood (gas drive) process with         significant pressure differentials between injection/production         wells.     -   THSAGDOX injects steam to improve combustion, and to cover the         production well with liquid to inhibit gas breakthrough. THAI         makes no attempt to add steam or to cover the production well.         Gas breakthrough is essential to the THAI process.     -   THSAGDOX injects steam and oxygen as sources of energy in the         reservoir. THAI injects compressed air.     -   THSAGDOX covers the production well and injects oxygen at a high         spot to prevent oxygen breakthrough to the production well. THAI         relies on a moving coke blockage formed upstream of the         combustion front in the horizontal producer to prevent air         (oxygen) breakthrough.     -   THSAGDOX injects water (and refluxes) steam to         encourage/stimulate lateral growth of the heated zone. THAI         relies on hot combustion gases/heat conduction for lateral         growth.     -   THAI has had a disappointing field test history.     -   THAI is (now) focussed on heavy oil EOR. THSAGDOX is focused on         bitumen EOR.     -   THSAGDOX can use sub-cool control on the production well to         ensure there is no gas or steam breakthrough to be produced.

(2) Distinction Between SWSAGDOX (FIGS. 17, 31, 31(a)) and SWSAGD (FIG. 20)

-   -   SWSAGDOX uses a mixture of oxygen and steam to deliver energy to         the reservoir. SWSAGD uses steam only.     -   SWSAGDOX has a version (SWSAGDOX(U)) (FIGS. 32, 33, 45) where         the toe of the horizontal well is drilled upward to segregate         liquid production and steam/oxygen injection. SWSAGD has as flat         horizontal well completion, where liquid flow to the producer         can flood the steam injector (FIGS. 20 & 52)     -   Both SWSAGDOX and SWSAGD operate as gravity drainage processes.         But due to the combustion component, the average T of the gas         chamber for SWSAGDOX is higher than saturated steam T for         SWSAGD.     -   SWSAGD has a disappointed history of field tests.     -   The combustion gases from SWSAGDOX migrate to the ceiling area         of the gas chamber (FIG. 42) and help insulate the interface to         reduce heat losses.     -   SWSAGD was focussed on thin pay heavy oil EOR. SWSAGDOX is         focused on thin pay bitumen EOR.

(3) Distinctions of THSAGDOX (FIG. 18) and/or SWSAGDOX (FIG. 30, 32) Compared to SAGD (FIG. 1)

-   -   SAGD uses 2 parallel horizontal wells. THSAGDOX and SWSAGDOX use         only one horizontal well.     -   SAGD is a 2D process—no longitudinal steam/liquid flows in the         longitudinal direction for a homogeneous reservoir. THSAGDOX and         SWSAGDOX are both 3D processes—the GD chamber (the gas and steam         swept zones) grow in a longitudinal direction (FIG. 28).     -   SAGD uses saturated steam. THSAGDOX and SWSAGDOX inject mixtures         of steam and oxygen (separately or together).     -   SAGD temperatures are limited to saturated steam T. The         combustion component of THSAGDOX and SWSAGDOX produces heat in         the reservoir at much higher T (600° C. vs 200° C.).     -   SAGD steam cannot vaporize water in the reservoir (connate         water, water in lean zones . . . ). THSAGDOX and SWSAGDOX can         vaporize reservoir water.     -   SAGD steam is used in a once-through process. THSAGDOX and         SWSAGDOX can reflux water/steam.     -   SAGD doesn't substantially produce any connate water. THSAGDOX         and SWSAGDOX produce connate water from the combustion-swept         zone.     -   Energy costs for SAGD (saturated steam) are significantly higher         than energy costs for THSAGDOX and SWSAGDOX.     -   SAGD is a net user of water (produced water recycle <100%). For         higher oxygen levels (>9%), THSAGDOX and SWSAGDOX is higher than         for SAGD.     -   SAGD has been successfully field tested. THSAGDOX and SWSAGDOX         are in the development phase.     -   SWSAGDOX and THSAGDOX are designed to focus on this-pay bitumen         (e.g. <25 metres thickness). SAGD focuses on thicker pays (>15         m)     -   SWSAGDOX and THSAGDOX can recover bitumen from the steam swept         zone. SAGD leaves significant residual bitumen behind the steam         swept zone.     -   Ultimate recovery for THSAGDOX will exceed SAGD recovery,         because THSAGDOX recovers bitumen from the steam-swept zone and         THSAGDOX can continue production to higher ETOR values because         energy costs are less.     -   SAGD is diluted with N₂. THSAGDOX vent gas is mostly CO₂,         suitable for sequestration.

(4) Distinctions of THSAGDOX (FIG. 26) Compared to COSH/COGD (FIG. 23)

-   -   COSH has 3 horizontal wells+3 (or more) vertical wells per         patter (FIG. 23). THSAGDOX has a single horizontal well and         single vertical well.     -   COSH relies on lateral horizontal vent wells to stimulate         lateral growth. THSAGDOX relies on steam to stimulate lateral         growth.     -   COSH has multiple vertical air injectors. THSAGDOX has a single         oxygen/team injector.     -   COSH uses compressed air as oxidant. THSAGDOX uses oxygen gas.     -   Neither COSH nor THSAGDOX have been field tested.     -   COSH vent gas is primarily CO₂ diluted with N₂. THSAGDOX vent         gas is undiluted CO₂.

(5) Unique Features of THSAGDOX:

-   -   co-injection of steam and oxygen     -   range of 0₂/steam (v/v) ratios     -   synergy between 0₂/steam     -   focus on bitumen reservoirs (<25 metres thickness, preferably         10-25 metres thickness)     -   multiple well versions (FIGS. 48, 40, 41, 57) for longer         horizontal wells     -   multiple combustion zone versions (FIG. 44)     -   oxygen insulation for team injection lines     -   tapered oxygen strategy—increase oxygen as project matures     -   focus on oxygen not air     -   TH geometry with multiple injectants, products.

(6) Unique features of SWSAGDOX:

-   -   single well process, 2 injectants, 2 products     -   features as above (5), (except for multiple well cases)     -   focus on thin reservoirs     -   updip completion versions (FIG. 49)     -   uplift toe versions (FIG. 32, 33) SWSAGDOX(U)     -   oxygen insulation for steam injection lines     -   focus on bitumen reservoirs, preferably thin reservoirs (e.g.         <25 metres, more preferably <15 metres)     -   SW geometry with multiple injectants, products

TABLE 1 Alberta Bitumen Deposits (10⁹ bbls) Athabasca Cold Lake Peace River Total Accessible Deposits (known technology) SAGD/CSS 420 51 54 526 Mining 59 0 0 59 Cold Production 13 138 0 151 subtotal 492 189 54 736 Unaccessible Deposits (no known technology) Carbonates 383 0 65 448 Thin Pays 380 21 8 410 No cap rock 37 0 0 37 Too deep for mining but 28 0 0 28 too shallow for SAGD Top gas 14 0 0 14 Others 36 −10 1 27 subtotal 811 11 74 962 Grand total 1369 201 129 1699 1. Source - Heidrick and Godin (2006) 2. Thin Pay (cut off = 10 m) 3. Numbers may not be additive due to rounding

TABLE 2 SAGDOX Injection Gases SAGDOX SAGDOX SAGDOX SAGDOX SAGDOX SAGD (5) (9) (35) (50) (75) % (v/v) oxygen 0 5 9 35 50 75 % heat from O₂ 0 34.8 50.0 84.5 91.0 96.8 BTU/SCF mix 47.4 69.0 86.3 198.8 263.7 371.9 MSCF/MMBTU 21.1 14.5 11.6 5.0 3.8 2.7 MSCF O₂/MMBTU 0.0 0.7 1.0 1.8 1.9 20 MSCF Steam/MMBTU 21.1 138 10.6 3.3 1.9 0.7 Where: (1) Steam heat value = 1000 BTU/lb (2) O₂ heat/combustion value = 480 BTU/SCF O₂ (3) SAGD = pure steam (4) SAGDOX (9) = 9% (v/v) oxygen in steam-oxygen mixture

As many changes therefore may be made to the embodiments of the invention without departing from the scope thereof. It is considered that all matter contained herein be considered illustrative of the invention and not in a limiting sense. 

1. A process to recover liquid hydrocarbons, from at least one thin pay zone in a hydrocarbon bitumen reservoir via a substantially horizontal production well wherein said hydrocarbon bitumen reservoir further comprises, a top and a bottom; said process comprising the use of Steam Assisted Gravity Drainage with Oxygen (SAGDOX) wherein: i) steam is injected into said hydrocarbon bitumen reservoir above said substantially horizontal production well, ii) oxygen is injected into said hydrocarbon bitumen reservoir above said substantially horizontal production well, iii) liquid hydrocarbon is recovered via gravity drainage into said substantially horizontal production well.
 2. The process of claim 1 wherein said steam is injected proximate said at least one thin pay zone.
 3. The process of claim 1 wherein said oxygen is injected proximate said at least one thin pay zone.
 4. The process of claim 2 wherein said oxygen is injected proximate said at least one thin pay zone.
 5. The process of claim 1 wherein said oxygen and said steam are injected into said reservoir at a ratio from about 0.05 to 1.00 v/v.
 6. The process of claim 1 wherein said substantially horizontal well further comprises a toe section and a heel section.
 7. The process of claim 6 wherein said toe section is at a first level in said reservoir and said heel section is at a second level in said reservoir.
 8. The process of claim 7 wherein said heel section is closer to said bottom and said toe section is closer to said top of said reservoir.
 9. The process of claim 1 wherein said SAGDOX has a Toe-to-Heel SAGDOX geometry.
 10. The process of claim 1 wherein said SAGDOX has a Single Well SAGDOX geometry.
 11. The process of claim 1 wherein said at least one thin pay zone is segregated from said hydrocarbon bitumen reservoir.
 12. The process of claim 1 wherein said at least one thin pay zone has a thickness of less than about 25 metres.
 13. The process of claim 1 wherein said at least one thin pay zone has a thickness of less than about 15 metres.
 14. The process of claim 1 wherein the substantially horizontal production well is used to produce water and liquid hydrocarbons and is completed within 2 m metres of the reservoir bottom.
 15. The process of claim 1 wherein the steam is injected within 20 metres from the substantially horizontal production well.
 16. The process of claim 1 wherein the oxygen is injected within 50 metres from the substantially horizontal production well; wherein said substantially horizontal production well further comprises at least one a perforation zone less than 50 metres in length.
 17. The process according to claim 16 wherein the oxygen and steam are controlled in the range from 0.05 to 1.00 (v/v) oxygen: steam.
 18. A process according to claim 17 wherein the ratio of oxygen to steam is increased during the process so that the oxygen/steam ratio (v/v) is maximized proximate the end of the process.
 19. The process of claim 9 wherein said THSAGDOX further comprises an uplifted toe section in said substantially horizontal well. 